The present invention relates to oil recovery techniques in which the recovery of oil from a reservoir is assisted by injecting a diluent into the reservoir formation to reduce the viscosity of the crude oil therein. Such techniques have been applied to the recovery of various oils, including the recovery of heavy oils and the enhanced recovery of medium and light oils. The diluent is intended to mix with the crude oil and form a mixture which has lower viscosity than that of the undiluted oil. One diluent which has frequently been proposed or used for this purpose is supercritical carbon dioxide. Another is low molecular weight liquid hydrocarbon which may be a distillation fraction such as naphtha. Mixtures of short chain alkanes, such as methane and ethane or propane and butane have also been used for this purpose, notably in the vapour extraction (VAPEX) process
A factor which has sometimes been overlooked, but which can be relevant and even be a potential obstacle to such techniques is the possibility of asphaltene precipitation within the reservoir formation. Asphaltenes occur in varying, and sometimes quite substantial amounts in crude oils. They are a group of organic materials in which the molecules contain fused aromatic ring systems and include nitrogen, sulphur and/or oxygen heteroatoms. They are accordingly more polar than the other fractions of crude oil (saturates, aromatics and resins). They are believed, by some researchers, to occur as colloidal suspensions in crude oil and are prone to separate out if the oil is subjected to a reduction in temperature or pressure, as frequently happens during production from an oil well. Asphaltenes separate out if crude oil is mixed with a less polar diluent (notably a low-boiling n-alkane) and they are generally defined as the fraction of crude oil which is precipitated by addition of n-pentane
or n-heptane but which is soluble in toluene.
The separation of asphaltene from crude oil has been variously referred to as flocculation, precipitation or deposition. A modern view is that nano-aggregates of asphaltene molecules flocculate to form a precipitate and this may deposit on adjacent surfaces. It is a well recognised issue that asphaltene may separate from crude oil and accumulate as an undesirable deposit within production, storage and transportation equipment. Remedial treatment of wellbores and near-wellbore regions with solvent and/or heat to remove deposited asphaltene is a regular commercial operation.
The flocculation and precipitation of asphaltene has been recognized to be a complex phenomenon. Buckley et al in “Solubility of the Least-Soluble Asphaltenes” which is chapter 16 of “Asphaltenes, Heavy Oils and Petroleomics” edited by O C Mullins et al (2007) see page 404 have reviewed work which understands asphaltenes to exist as a colloidal suspension in crude oil, with resins playing a role (which has not yet been fully explained) in maintaining the stability of such a suspension. On this understanding of asphaltene suspension, it appears that an interaction between the resin and added diluent can induce flocculation and precipitation. J G Speight in “The Chemistry and Technology of Petroleum” 3rd ed (1999) pages 415 and 417 gave a list of nine physical and chemical parameters relevant to asphaltene separation.
The exact nature of this phenomenon of asphaltene precipitation is not yet completely understood and so it is not clear what theoretical model should be applied to it, nor even whether any theoretical model can be justified. However, a number of documents have discussed the characterisation of crude oils to predict the likelihood of asphaltene precipitation. Takhar et al in “Prediction of Asphaltene Deposition During Production—Model Description and Experimental Details,” Society of Petroleum Engineers paper 30108, 311-316, May 1995, referred to titration experiments, which make controlled additions of an n-alkane until the onset of precipitation, as a way to check a crude oil's “spare solvency” for asphaltene. Gonzalez et al in “Asphaltenes from Crude Oil and Hydrocarbon Media” Energy and Fuels, vol 20, pages 2544-2551 (2006) reported the use of a fairly similar procedure with several crude oil samples, and confirmed the existing understanding that the stability of asphaltene within a crude oil varies considerably from one oil to another (an oil is termed ‘unstable’ if precipitation can be induced by small changes in pressure or temperature or by the addition of a small amount of diluent).
Many literature references discuss models for asphaltene precipitation. Among them, there have been a number of suggestions that the “onset” conditions under which precipitation of asphaltene commences as the n-alkane concentration increases can be described in terms of Hildebrand solubility parameter (even though the theoretical basis for that parameter is in real solutions not colloidal suspensions). Mitchell and Speight, in “The Solubility of Asphaltenes in hydrocarbon solvents” Fuel vol 52, pages 149-152 (1973) reported an inverse correlation between asphaltene precipitation from Athabasca bitumen and the Hildebrand solubility parameter of added hydrocarbon which caused precipitation. There was no precipitation when the Hildebrand solubility parameter of the added hydrocarbon was 16.8 or above. Buckley et al in “Solubility of the Least-Soluble Asphaltenes” referenced above, see pages 409-412, commented that a number of authors had concluded that the onset of asphaltene precipitation occurs when the mixture of added diluent and oil is such that its overall Hildebrand solubility parameter is at a critical value. However, Buckley et al went on to demonstrate that this was not a reliable conclusion from the data. They reviewed data of their own to show that the solubility parameter at the onset of precipitation “varies significantly with dilution”.
K A Frost et al, in “New, Highly Effective Asphaltene Removal system with Favorable HSE Characteristics” Society of Petroleum Engineers paper 112420, February 2008, described the use of both Hildebrand solubility parameter and the more detailed system of Hansen solubility parameters to characterise solvents to include in emulsions for removing asphaltene as a wellbore remedial treatment.
It has been recognised that asphaltene can precipitate within a formation if a viscosity reducing diluent is injected into the formation and that this can cause significant formation damage. Hwang and Ortiz in “Mitigation of asphaltics deposition during CO2 flood by enhancing CO2 solvency with chemical modifiers” Organic Geochemistry vol 31, pages 1451-1462 (2000), investigated the effect of adding various solvents to supercritical carbon dioxide used to enhance oil recovery. The amount of added solvent was arbitrarily set at 10% of the carbon dioxide and solvent mixture. They demonstrated that addition of various solvents and solvent mixtures to the carbon dioxide achieved a much greater extraction of oil with a reduced amount of carbon dioxide and also reduced the amount of asphaltene remaining in the geological formulation compared with using carbon dioxide alone. The solvents which were tried were toluene, a light aromatic hydrocarbon mixture, alcohols, and mixtures of alcohol and toluene.
US2007/295640 proposes treating a formation with a composition containing a viscosity reducing diluent (which was a substance that would be an asphaltene precipitant if used alone) together with an asphaltene solvent. Possible precipitating diluents include light hydrocarbons as well as carbon dioxide. The compounds suggested in this document as asphaltene solvents are aromatic and substituted aromatic compounds. This document makes a suggestion that the diluent, the asphaltene solvent and any other additives may be related to each other (but only to each other) by solubility parameters.
Some other documents can be identified, in retrospect, as utilising mixtures in which an asphaltene solvent was present. U.S. Pat. No. 4,004,636 taught a process of treating a tar sand formation with a multiple solvent system containing both a first component which is the liquefied form of a normally gaseous material such as carbon dioxide or a short chain hydrocarbon and a second component which is a normally liquid hydrocarbon. Suggested normally liquid hydrocarbons included some such as hexane which are asphaltene precipitants and some such as toluene which are asphaltene solvents. The former category, eg hexane, was preferred on economic grounds and it was reported, expressing some surprise, that these did not cause asphaltene precipitation. The intention was that the first component of the mixture would revert to its gaseous state within the reservoir formation and drive oil from the reservoir towards a production well, while the normally liquid hydrocarbon acted as solvent. Similar disclosure is found in U.S. Pat. No. 3,954,141 and U.S. Pat. No. 4,007,785, while U.S. Pat. No. 4,071,458 and U.S. Pat. No. 4,026,358 use an aromatic solvent saturated with carbon dioxide as the diluent. U.S. Pat. No. 5,139,088 taught a process in which an aromatic fraction of the extracted oil was recirculated into the reservoir formation to act as the diluent, but this recirculated fraction was not mixed with other diluent material.
U.S. Pat. No. 5,117,907 taught enhanced oil recovery using supercritical carbon dioxide to which trichloroethane was added in order to increase density and viscosity of the supercritical carbon dioxide. U.S. Pat. No. 4,800,957 taught the use of alcohols or ethylene glycol as additive to supercritical carbon dioxide for a similar purpose. These documents do not suggest that there was any asphaltene precipitation even in the absence of the additive.